A_Compilation_of_Success_Stories-PNWSGDP

B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Pacific Northwest Smart Grid
Demonstration Project
A COMPILATION of
success stories

To learn more visit:
www.bpa.gov/goto/smartgrid
Or contact:
TechnologyInnovation@bpa.gov

02 Letters from BPA and Battelle
05 Avista
11 PGE
15 University of Washington
19 Idaho Falls
23 Flathead Electric Co-op
27 NorthWestern Energy
31 Milton-Freewater
35 Lower Valley Energy
39 PenLight
43 City of Ellensburg
47 Benton PUD
51 Glossary

2
The Bonneville Power Administration invests in the Northwest’s energy future. Through its
Technology Innovation program, BPA funds an annual portfolio of projects that advance technologies and
enable breakthroughs and operational improvements in support of BPA’s mission of providing low-cost,
reliable electric power to the Pacific Northwest. BPA’s research goals, as outlined in its strategic direction and
technology roadmaps, focus on key areas such as advancing energy efficiency technologies, preserving and
enhancing generation and transmission system assets, and expanding balancing capabilities and resources.
Since 2005, Technology Innovation’s disciplined research management approach has led to unprecedented
levels of success.
BPA works closely with the U.S. Department of Energy and Electric Power Research Institute, and continues to
strategically expand its partnerships with electric utilities, universities, researchers and technology developers.
Technology Innovation has led the collaborative development of roadmaps that pinpoint the technology
needs for the electric power industry for the next five to 20 years. To date, BPA has partnered with industry
experts, researchers and others to develop technology roadmaps for energy efficiency, transmission and
demand response. These roadmaps now serve as a resource for BPA and others to prioritize their technology
investments and identify partnership opportunities.
BPA’s R&D investments deliver savings of millions of dollars in avoided costs and increased efficiencies,
and result in a smarter, more dynamic, efficient and reliable Northwest electric power system. Today, BPA is
investing about $17 million annually in R&D, which is nearly five times the U.S. industry average. The largest
project in the TI portfolio is the $178 million Pacific Northwest Smart Grid Demonstration Project. The nation’s
largest smart grid demonstration project involves 60,000 metered customers across five states, 11 public
and private utilities, two universities and six infrastructure partners. Through BPA’s $10 million cost-share
contribution, the project has deployed $80 million in new smart grid technologies in the Northwest, setting the
stage for regional smart grid growth.
Terry Oliver
BPA chief technology innovation officer
Letter
from
BPA

3
When we embarked upon this ambitious project in 2010, we began an exciting, and highly
challenging, journey. It was not an entirely new endeavor — we were building on the earlier GridWise® Olympic
Peninsula demonstration. But no project had tackled the breadth and scope of implementing a key new smart
grid technology called transactive control, for coordinating demand response from 11 utilities across a five-state
region. In addition, participants identified their own individual smart grid technology objectives. In all, the project
will have evaluated about 80 different technology test cases. Like any project of this size and nature, we worked
our way through perplexing technical issues and challenges we didn’t anticipate, but we also experienced
rewarding accomplishments.
This booklet chronicles the Pacific Northwest Smart Grid Demonstration Project’s successes. It’s exciting to
read about Lower Valley Energy’s great experience with water heater demand response, Portland General
Electric’s creation of the Salem Smart Power Center, the University of Washington’s broader understanding of
electricity consumption in campus buildings, and Avista’s visionary work in establishing a smart grid city. There
are a number of successes to report among the participating utilities, and I hope you’ll take time to peruse
the articles and learn more about other examples of progress. It’s also illuminating to read about aspects of
the project that didn’t turn out as planned — essentially “lessons learned” that, along with successes, will be
important in informing the industry for future smart grid technology deployment.
Battelle and the other participants in this demonstration are pleased and proud to have been a part of a
monumental project that reflects the unique grid-related capabilities — and ingenuity — of the Pacific Northwest. I
have no doubt that this project and the knowledge that has been gained will successfully prepare the region for
a bold energy future that strengthens our economy, protects our environment and enhances our quality of life.
Ron Melton
Battelle project director
Letter
from
Battelle

5
Pacific Northwest Smart Grid Demonstration Project
success stories
Avista
Creating a smart city by focusing on
grid efficiencies
Before Washington was granted statehood, the utility
known as Avista had already built the world’s longest
transmission line and would later go on to create the
country’s first electric stove. Today, Avista’s rich history
of innovation is being applied to one of the greatest
challenges facing the energy industry — integrating
new technologies. Avista’s vision for modernizing its grid
resulted in the region’s first smart grid city as part of the
Pacific Northwest Smart Grid Demonstration Project.
With an investment of $19 million, matched
by funds from the Department of Energy,
Avista has the momentum to deploy a
system-of-systems architecture model.
Washington State University partnered
with Avista as part of its project.
As Avista’s funding accelerated, so did the
pace of the upgrades. Yet the approach
to planning one of the region’s first smart
cities remained strategic and forwarding-
looking.
The case for a system
of systems
“You have to look at the business case with
respect to the current reality and potential
new realities,” said Curtis Kirkeby, Avista’s
principal investigator for the smart grid
demonstration. “The economics that
we have used forever in utilities may not
be the economics that are actually valid
anymore.”
Instead of looking at one particular system,
Avista’s business case for smart grid
AVISTA Corporation
Spokane, Washington
ƒƒInvestor-owned utility since 1889
ƒƒ125-year history of innovation
ƒƒ30,000 square-mile service territory
ƒƒServes population of 1.5 million in
eastern Washington, northern Idaho
and eastern Oregon
ƒƒElectricity and gas service
ƒƒ359,000 electric customers
INVESTMENT
$19 million
HIGHLIGHTS
ƒƒVoltage optimization
ƒƒCapacitor bank controls
ƒƒSmart transformers
ƒƒCustomer thermostats and apps
ƒƒWSU air handlers, chillers
and generators
FOR MORE INFORMATION
Curtis Kirkeby (509) 495-4763
www.avistautilities.com

6
An Avista dispatcher is able to see, in real-time, the current state of portions of Avista’s
distribution network.
concentrated on a much broader set of
objectives, with a deliberate focus on
interoperability and the ability to share
information across multiple systems.
“It made for strong solutions as we move
forward,” said Kirkeby. “You don’t want
to limit yourself or short the vision.”
After all, to create a smart city, scale
is important.
“Our goal was to do everything possible
that would result in better operation of our
system. At the same time, we wanted to
maximize reliability, system efficiency and
the customer experience. We knew that’s
where we would find the greatest value,
when we could achieve all three of these
objectives,” said Heather Rosentrater,
Avista’s director of engineering.
Smart circuits set
the stage
First, Avista upgraded electrical facilities
and automated the electrical distribution
system in Spokane and Pullman. A
distribution management system was
put in place to serve as the brains for the
smart city, along with intelligent devices
and a communications system to benefit
more than 110,000 electric customers.
Smart circuits reduce energy losses, lower
system costs and improve reliability and
efficiency in the electricity distribution system.
The system efficiencies will save about
42,000 megawatt-hours per year, enough
to power 3,500 homes, and prevent
14,000 tons of carbon from being released
into the atmosphere from power generation.
Problem areas on the system are instantly
identified by the advanced distribution
management system, which was deployed
for one-third of the customer base. A whole
new level of information is displayed,
which can be operated manually or fully
automated around the clock — not
a typical installation. The distribution
management system features predictive
applications and auto-restoration
technology.
The new, advanced distribution manage-
ment system revolutionizes how the
system is designed, built, tuned and
operated. Real-time power management
systems require an accurately maintained
calculation model so that the distributed
resources can be managed regardless of
location.
Smart transformers
Every home or business uses different
amounts of energy that’s distributed
through a transformer on a pole to multiple
sites. Smart transformers installed in the
Pullman area gather information about how
much energy each transformer supplies,
so Avista can determine the appropriate
size transformer to meet customers’ energy
needs. The “right sizing” of transformers
makes the distribution system more efficient
as energy is delivered to customers.
Biggest bang for
your buck
Efficiency equals managing voltage and
power factors.
Using voltage optimization, the utility can
lower the voltage on the feeder — the line
from a substation to the home or business —
to minimize the loss of electricity.
“As we scoped the project, we realized this
is where the biggest bang for the buck
is,” said Kirkeby. “This is where the real
dollars are. We estimated 1.86 percent
savings by applying this technology to
the feeders in Pullman on WSU’s campus
based on a regional study, but we’re
actually seeing 2.5 percent.”
There’s also still room to grow this efficiency
savings. Fine tuning continues.
“Be part of the study
that may change
everything”
The two-way communication foundation
requires installation of advanced meters at
the customer’s location. All of Pullman and
Albion — a total of 13,600 customers —
now have advanced meters. The digital
meters operate via a secure wireless
network, allowing two-way, real-time
communication between the customer’s
meter and Avista.

7
Smart thermostat pilot participants
received a free thermostat.
We upgraded your meter to a digital
advanced meter so you can save energy.
As part of Avista’s Smart Grid Demon-
stration Project, you've been given a new,
smarter meter. Advanced meters allow a
secure, two-way wireless communication
between your meter and Avista.
This means you can now access an online
portal to view your usage down to the hour,
make adjustments, and start saving
energy. You’re helping us learn how new
technologies can enhance the safety,
reliability and efficiency of energy delivery
for all of our customers.
LOG ON. ADJUST. SAVE!
Use your advanced meter dashboard to manage your home’s energy use:
portal to view your usage down to the hour,
energy. You’re helping us learn how new
technologies can enhance the safety,
reliability and efficiency of energy delivery
for all of our customers.
Use your advanced meter dashboard to manage your home’s energy use:
Compare daily energy
use with outside
temperatures.
Track your hour-by-hour
daily usage.
See the ways that your
home uses energy.
Log in to your account at
avistautilities.com and
click on the “My Advanced
Meter” icon.
WATCH a QUICK TUTORIAL »
We upgraded your meter to a digital
advanced meter so you can save energy.
As part of Avista’s Smart Grid Demon-
stration Project, you've been given a new,
smarter meter. Advanced meters allow a
secure, two-way wireless communication
between your meter and Avista.
LOG ON. ADJUST. SASAS VAVA E!
Log in to your account at
avistautilities.com and
click on the “My Advanced
Meter” icon.
SIGN IN NOW to START »
To learn more, please visit avistautilities.com/smartgrid.
You will need an account to access your online reports.
Don’t have one? Sign up now at avistautilities.com.
© 2012 Avista Corporation. All Rights Reserved
Avista’s marketing campaign used inspirational language to recruit volunteers.
“We didn’t have any opposition to putting
advanced meters there, which may not be
typical across the country,” Kirkeby said.
Building awareness and understanding
among customers was critical to successfully
deploying new technology and engaging
people. Inspirational key messages were
disseminated through focus groups, targeted
email and direct mail, print advertising,
town meetings and board meetings. Cutting
through the clutter of busy lives was
challenging. Customers responded best
to the in-person communication.
“They had the feeling that they were part
of a project of national importance. The
research aspect of our work resonated in
a college community like Pullman. It was
a feel-good thing for the customer — they
felt like they were making a difference,” said
Laurine Jue, a senior communications
manager at Avista.
A dedicated point of contact was critical to
answer tough questions about the pilot.
Smart thermostat pilot
The smart thermostat pilot was one of the
customer-experience components of the
project. Customers who volunteered to
participate in the two-year pilot received
a free smart thermostat, plus $100 per year in
exchange for allowing the utility to remotely
adjust the thermostat by 2 degrees
Fahrenheit for a period of 10 minutes to
24 hours. The customer could always
override the setting at any time.
“You can set up a program to override
at any point,” said Joshah Jennings, a
smart thermostat pilot participant.
Settings, including alerts, can be adjusted
directly, over the Internet or with a smart
phone. Using the application on a regular
basis keeps energy usage “top of
mind” for customers. Participants could
view energy usage down to the hour,
energy. A price curve was set for hourly
consumption. For the Jennings, a fiscally
conservative family of five, saving money
is important.
“But being a technology buff too, it was kind
of fun to play with the new technology,”
Jennings said.
All customers with the smart thermostats
also had advanced meters that provided
usage data. At the end of the pilot, data
indicated that smart thermostat participants
reduced consumption between 4.5 and
9 percent.
AVISTA TIP: The thermostat was designed
so that the vendor and its product were
not dependent on Avista — the connection
was through public Internet. The thermostat
read the meter and sent data back to
the thermostat vendor through its own
mechanism. That means no maintenance
for Avista.
Energy Analyzer needs
actionable items
Another aspect of the customer experience
was giving customers access to information
about their energy use. Using a web portal,
called the Energy Analyzer, customers could
log in to their account to see their energy
use patterns and make informed decisions
about choices that drive energy costs.
The launch of the web portal was promoted
with direct marketing and an online video to
help educate customers about how to use
it. While some customers looked at the
portal frequently, most customers did not
find it compelling. Although the average
site visit was six minutes and 36 seconds,
access to the web portal did not result in
a measureable change in consumption.

8
One of the main factors that could have
contributed to this is the absence of time-
of-use rates, which could directly impact
customers’ usage patterns. Plus, every
customer has a preferred method for
accessing information, whether it’s direct
mail, email, a website or a mobile device.
Avista suspected that if an actionable
item doesn’t result from the data, it’s not
something a customer will get excited
about. If a customer wants a lower bill,
suggestions based on the data provided
would be more useful.
“That’s why we launched a texting pilot,”
said Kirkeby. “It allowed customers to
opt-in to receive daily or weekly usage
updates via text or email, which included
usage predictions based on all kinds
of factors. Weather factors, household
factors and HVAC factors are useful to
a customer trying to manage their bill
through their own efforts.”
“All of the work that we did in Pullman
really has helped our customers understand
on a personal level what Avista is doing
to modernize our grid,” said Rosentrater.
“What it means for customers is improved
reliability; they’re going to experience
fewer and shorter outages. What used to
take hours to restore, can now be done
in minutes.”
Washington State University was a centerpiece of Avista’s smart city in Pullman.
In the long run, fewer and shorter outages,
plus options for saving energy, matter
most. It’s a big win for customers.
A big win for
Washington State
University
As a key partner in the project, Washington
State University brought its best minds
and dozens of facilities to the table. The
campus can now be operated as a
microgrid with the ability to control
both loads and generation resources
on campus, as well as respond to a
transactive control request from Avista
based on regional grid needs.
Working with Avista and with WSU
professors Anurag Srivastava and Anjan
Bose, students helped simplify the process
for computing real-time savings from
improved power factors and voltage
reduction. They also developed new tools
for reliability benefit calculations, for data
transfer between software tools and for
real-time load characteristic estimations.
The project resulted in award-winning
work and provided valuable, hands-on
experience to prepare students to be
leaders in the 21st century power industry.
With its cost-share investment of
$2.1 million, WSU also installed 88 smart
electric meters, providing direct feedback
to Avista for voltage optimization of
the campus power circuits, and built
sophisticated building control programs
to automate its chillers, air handlers and
three generators for smart grid operations.
For example, the air handlers in
29 campus buildings used to run without
consideration of building occupancy
levels. Air handlers ensure the air quality
in buildings is consistent. With the new
programs, the air handlers automatically
ramp down when occupancy levels are
low and ramp up before higher occupancy
periods. While the technology doesn’t
change what happens within the building,
it optimizes the efficiency of the system
by scheduling appropriate actions based
upon campus needs.
“Their systems are smart enough to be able
to manage all air handlers individually to get
to some level of cumulative benefit,” said
Kirkeby.
The voltage optimization and new air handler
programs save the university a lot of money;
it expects to save about $150,000 a year.
Each one of the controllable assets can be
managed in a much more efficient way and
fine-tuned as conditions change.

9
It’s been really exciting! A year and a half after
the distribution management system went live,
we hit our one-millionth avoided outage minute.
That’s a tangible benefit for our customers.
Avista is also realizing benefits – we’ve learned
so much and we’re applying these lessons
every day.”
– Heather Rosentrater, Avista director of engineering
Students helped to simplify the process
of validating real-time savings from power
factor and voltage reduction. A new tool
was built to validate, or at least estimate
with a high degree of accuracy, every
circuit that’s involved in the system for
every five-minute interval.
Avista generates
a request
These generation assets are also connected
to Avista’s distribution management sys-
tem through an Avista Generated Signal.
Avista can generate a request to reduce
those loads or generate power for various
needs.
“If you think back to the energy crisis in
2000 when, in the Northwest, we were all
looking for generation, now we have a push
button for three of them,” said Kirkeby. “All
Avista does now is make a request and
they can be online.”
For the smart grid demo, a transactive
control signal request came from Battelle.
Avista then translated that into an Avista
Generated Request Signal that went to
WSU, asking for one of five tiers: one tier
for air handlers, one tier for chillers, and
three different tiers for generators.
Avista’s request asked for deployment
of certain assets based on the request
from Battelle. A WSU facilities operator
decided whether or not to honor that
request. If not, software sent Avista a
text explaining why. Automatic texts were
also generated. Codes were built into
the system so that it still functions even
without the transactive signal.
“Being a part of this pilot project has really
opened doors for improved communica-
tions, metering, power system operations,
and building controls, which provide the
tools for WSU to assist with regional
needs while also reducing our operating
costs,” said Terry Ryan, WSU director of
Energy System Operations.
Win! Win! Win!
Leveraging university assets is a model that
Avista believes can be used elsewhere.
After all, utilities and universities alike are
always looking for ways to reduce costs.
“That’s exactly what we did,” said Kirkeby.
“It’s a win-win-win for WSU, Avista and
for the region.”
The project also greatly improved cyber
security across the utility footprint. National
Institute of Standards and Technology
guidelines were used to assess risk.
Then a mitigation measure was assigned
to each risk to determine whether to
proceed or how to proceed.
By participating in the project, Avista
learned in a real-world environment the
benefit stream from each component in a
particular use case, and which pieces will
extend well beyond the project and into
the future to create an ultimate smart city
configuration.
Some pieces of that puzzle are important
lessons learned.
Learn! Learn! Learn!
It’s not always easy to change an
established paradigm, especially when
redesigning business processes around
technologies such as automating grid
control. Even some vendors pushed back.
“Some said: you don’t really want
automation,” said Kirkeby. “To which we
responded, ‘Yes! We really do!’ That’s why
we’re doing this. We don’t want an army
of people operating it; we want it to be
automated.”
When working with vendors, “It always
comes down to relationships and
partnerships,” said Kirkeby.
Ironically, the very people expected to
push back on automation were the most
supportive: the linemen. For them, doing
away with mundane tasks was positive.
For others, it took trust that the system
wouldn’t make mistakes and that, if it
did make a mistake, consequences were
managed.
Creating a smart city meant embracing
change. It’s everywhere.
“We’ve changed as part of this project,”
said Kirkeby. “We’ve revised the design,
engineering and equipment standards
going forward. We’ll add to those standards
as new learnings come about and as we
add more technologies or benefit streams
we find.”

10
The future is an evolving
vision. The grid will be a
system that’s flexible,
scalable and under-
standable by the people
building it. Avista’s
roadmap includes a grid
modernization program
budgeted for the next 25 to 30 years.
“We’re trying to be really proactive and create the utility
of the future now,” said Rosentrater. “So we’re trying to
figure out as a utility where we need to be, what we need
to do to provide the most value to customers, and where
customers will value us — value what we do and keep
our business viable.”
With an increased capital budget for grid modernization,
Avista is leveraging what’s already in place to advance
the rest of the system. Armed with a smart grid roadmap
from the demonstration, each feeder in Spokane will be
modernized. In Pullman, a new battery unit is already in
the works as part of a Washington State Department of
Commerce grant. Avista will explore how battery storage
capabilities can be integrated onto the grid to address
the intermittent energy from renewable power.
Participating in the Pacific Northwest Smart Grid Dem-
onstration project gave Avista the opportunity to realize
the “endless” possibilities. And the many lessons learned
have provided a solid foundation for Avista as it contin-
ues to modernize the grid to meet the energy needs of its
customers well into the future.
What’s
next
for Avista?

11
Portland
General
Electric
Smart power in store for the future
Getting smart about electricity has never been more exciting.
That’s especially true at Portland General Electric – Oregon’s
largest investor-owned utility. PGE’s Salem Smart Power
Center is a new five-megawatt battery storage facility that
is part of the larger Pacific Northwest Smart Grid Demon-
stration Project. This first-of-its-kind facility is one of the
most advanced electrical systems in the nation and, as such,
has inspired the imagination of a region. Energy storage is
just one of the new technologies being tested by the proj-
ect to integrate renewable energy, improve grid reliability
and lower costs to customers.
With the foundation of a smart grid already
in place — 800,000 smart meters — PGE
was inspired to integrate several smart
grid programs into one effort. It was an
endeavor much larger than PGE could
tackle on its own. The heart of it centered
on the Salem Smart Power Center.
“A five-megawatt lithium-ion battery system
that is grid-tied is very rare in the electricity
business,” said Wayne Lei, director of
R&D for PGE. “It’s one of just two owned
and operated by an investor-owned utility.”
Big – really big –
batteries
Lithium batteries are widely used because
of their high-energy density — the ability
to store a lot of energy in a lightweight,
compact form. It’s the same battery
technology used in laptops and cell
phones but on a much larger scale. The
key feature of the 8,000-square-foot
center is a five-megawatt lithium-ion
battery-inverter system. The bank of
batteries stores 1.25 megawatt-hours of
Portland General Electric
Portland, Oregon
ƒƒFounded in 1889
ƒƒOregon’s largest invester-owned utility
ƒƒServing 52 communities across
Oregon
ƒƒ842,000 customers
ƒƒ13 power plants with capacity of
2,781 megawatts
INVESTMENT
$6.5 million
HIGHLIGHTS
ƒƒDistribution microgrid
ƒƒFive-megawatt lithium-ion battery
ƒƒIntelligent distribution management
ƒƒCommercial demand response
ƒƒDemonstrates renewable integration
Kevin Whitener (503) 464-8219
www.portlandgeneral.com
success stories

12
What is a microgrid?
A microgrid is a small-scale version of
an electrical grid. It can be “islanded,” or
disconnected from external transmission
services. Local distribution provides power
for customers’ electrical needs with only
local generators and battery storage.
energy, which allows PGE engineers and
planners to demonstrate high-reliability
strategies involving intentional islanding
of the feeder, distribution automation
using smart switches, demand response,
renewable energy integration and auto-
matic economic dispatch.
Building the battery facility was an under-
taking. But integrating the technologies
was the real feat. It required a dedicated
engineering team to address the complex
challenges that arose in bringing this
innovative facility to life. After all, many of
the technologies implemented were new
to the market.
“We underestimated what it takes to attach
a five-megawatt battery to our own system,”
said Kevin Whitener, the lead engineer
for the project. “The complexity and the
engineering challenge of doing that is
something we hadn’t fully anticipated.”
Thousands of battery cells are stored in
racks and wired together into a single
system. Batteries use direct current while
the distribution system uses alternating
current, so inverters sit between the grid
and the batteries. This allows power to flow
in either direction, converting from AC to
DC and back on demand. Coordinating the
communication between the systems and
components was substantial and complex.
For example, between the inverters,
the battery management system and
the other controllers in the facility,
there are five different communication
protocols. There are sixty-seven
separately addressed internet devices
communicating on two different networks
within the facility. That created a lot of
data handling challenges.
“The protocols had to be sorted out and
interfaced together,” said Whitener.
“There’s no way to do that short of
spending weeks and months struggling
to get it to work. But we did it.”
The safety of employees and the public is
important to PGE, which is why the Salem
Smart Power Center was constructed
with a focus on safety. Due to the high
energy density of the large battery, a
unique fire control system was specially
designed for the lithium-ion application
that includes giant fans that keep the
batteries cool at all times.
Creating a microgrid
with macro resiliency
A microgrid improves a system’s
resiliency by allowing the utility to
segment a certain part of the feeder and
to provide back-up electricity during
an outage. When a substation loses its
power supply from the transmission lines,
the battery system starts immediately,
serving as an uninterruptable power
supply.
If an outage were to occur in Salem, all
residential, commercial and industrial
customers on the circuit can be supplied
electricity from the battery’s 1.25 mega-
watt-hours of energy for 15–20 minutes.
This is more than enough time to start
the six customer-owned distributed diesel
generators and synchronize them on the
line. Once the feeder is isolated from the
utility grid, the generators start up, and
the circuit becomes a microgrid.
PGE has been working for more than
10 years to establish cooperative
microgrids with customers that own
standby generation. Together, they have
built the nation’s largest distributed gen-
eration program which shares customer
generation with the utility in times of
need. Many of PGE’s large customers
have local diesel generation on site to
prevent a power outage in case of an
emergency. By partnering together, PGE
is able to tap into this standby generation
during an outage situation. The result is a
highly resilient system.

13
Our electrical grid in the United States is one
of the greatest accomplishments of the 20th
century. Portland General Electric and its
partners are demonstrating new technologies
that hold promise for building a more efficient,
sustainable and reliable grid. As these
technologies became cost effective they can
provide the opportunity to reshape not only
the infrastructure that makes up the grid,
but the approach utilities take to meeting the
needs of our customers, the economy and the
environment in the 21st century.
— Jim Piro, PGE CEO and President
A High Reliability Zone
PGE named its microgrid a “High Reliability
Zone.” The HRZ includes the large-
scale energy storage system, customer
standby generators and distribution
automation components. These compo-
nents, called smart switches, quickly
sectionalize the microgrid in case of a
fault, like a downed power line. The
switches bring an even higher level of
reliability to customers.
Unlike a standard feeder switch, which
must be manually operated to change
or stop the flow of power on a feeder,
a smart switch “senses” changes in the
feeder, like a fault, and activates the
switch automatically. This changes the
physical configuration of the feeder within
seconds.
It’s a microgrid that heals itself.
For solar, it’s all in
the algorithm
One of the most exciting parts of the
project for PGE was exploring solutions
to integrate renewable energy into the grid
using battery storage. A key challenge
to using solar as a power source is
that sunshine is intermittent, especially
in Oregon. Using an algorithm, PGE
demonstrated how solar energy can be
combined with a battery to fill in the gaps
when the sun isn’t shining and offer a
seamless power flow.
With more than 6,000 megawatts of
intermittent wind and solar power sweeping
the Pacific Northwest electrical grid, the
project provided an opportunity to learn how
to best partner with customers to deliver
high reliability. To test the integration, PGE
used the solar output from the local potato
chip maker, Kettle Brand, and then aimed
to levelize, or fill in the blanks of this irregular
output, using the battery.
Here is how the process works. First,
an instantaneous measurement is taken
of the customer demand on the circuit.
Then a measurement is taken of the
instantaneous power output from Kettle
Brands’ solar plant. This information is
compared to the theoretical ideal load for
the utility’s circuit. The battery makes up
the difference in the output in real-time,
either filling in the gaps where the clouds
caused output to fall short of the best
possible power or charging the batteries
when the output from the panels is higher
than normal.
“This is one of the few opportunities that
the industry has had to prove these
concepts and demonstrate that energy
storage is indeed a solution to integrating
solar energy,” said Whitener. “Impacts from
what we’re doing here are far-reaching.”
An interesting exhibit
The Salem Smart Power Center has had
many curious visitors. Tours feature a
video reviewing the safety of the system,
smart grid exhibits and an educational
gallery with views into the operations
center. Schools, other utilities, industry
suppliers, consultants and government
representatives all wanted to see this
state-of-the-art facility.
“We’ve had more than 1,200 people visit
the facility and learn about the project,”
said Whitener. “That’s pretty astonishing.”
Partnering with
customers
PGE’s smart meters enable a two-way
conversation between PGE and its
customers, helping the utility to optimize
its services, add convenience and lower
energy costs. As part of this demonstration
project, residential and business customers
were enlisted to respond to grid conditions
by reducing energy during peak times or
during a test.
“The utility can decrease the load at peak
times of use, or shift loads from one
period to another,” says Carol Mills,
PGE’s senior project manager. “The
objective was to offer demand response
assets that could respond to the project’s
integrated systems.”
Although PGE installed a demand response
management system in Salem, a ‘human
in the loop’ was used to ensure the
programs would be initiated and observed
carefully when called into action.

14
An impressive
transactive system
As part of this project, PGE is testing
ways in which we can automate renewable
integration and demand response op-
portunities to ensure customers receive
the most benefit from energy resources
for the least cost. The project includes
testing a transactive system, an informa-
tion system that automatically shares
real-time data between computers at
utilities and the transmission coordina-
tor. Similar to how utilities get information
from wholesale power markets today, this
system sends out a price signal every five
minutes, which reaches a multiple utility
footprint at the same time. The signal
shows how the price of power is expect-
ed to change over the next three days.
Utilities then respond with a load forecast
based on that string of future prices.
This allows a system coordinator, in this
case the Pacific Northwest National
Laboratory, to calculate where the
entire grid may have congestion issues
in advance. The process is then repeated
every five minutes, allowing for planning
around congestion and prices to occur for
everyone in the system.
Using artificial
intelligence
Although, automating the electricity market
is still in testing stages, strides were made
learning about which tools are needed for
its development.
“We’ve proven that we can dispatch
resources at the command of the trans-
active node,” said Whitener.
The transactive node, which PGE calls
the Smart Power Platform, is the main
computer program that optimizes the
economic decisions about the smart grid
assets: when to dispatch, when to charge
or discharge the battery, and when to use
the demand response capability. The
node responds to a signal from PNNL.
To interact with the signal, PGE wrote
its own software program using artificial
intelligence. Neural networks analyze the
thousands of data points in the system
and respond to the transactive signal. The
computer absorbs all that information,
synthesizes it, and makes a decision.
“We were able to demonstrate the ability
of the computers on both sides to learn
and get better at optimizing power for
the least cost to customers,” said Lei. “It’s
literally a monetary estimation in terms of
the value to deliver and the value to acquire
that power.”
Learning from
unique systems
Virtually all systems tested by PGE were
new and unique. The Salem Smart Power
Center demonstrated the ability to island
a microgrid with utility-scale storage and
customer standby generation, operate
demand response, respond to a transactive
signal, and how to integrate these complex
resources into a single control system. As a
result, PGE offered several key takeaways:
ƒƒ Take full advantage of consulting talent
both within and outside the company
to assess risk and make plans to
mitigate that risk.
ƒƒ Reduce financial risks by using
government funds when possible.
ƒƒ When it comes to a first-of-its-kind
project, testing is your best friend. PGE
sought to protect customers by ensuring
the systems were reliable and robust.
Perform and document lots of testing,
especially when there is a potential to
impact commercial and residential
customers.
ƒƒ Thoroughly vet vendors’ capabilities
and financial strength. Smart grid
technology is a growing industry, full of
emerging companies. Ensure those
companies are well-capitalized.
ƒƒ To ensure the safety of employees and
the public, it’s critical to have a robust
set of safety requirements in place that
serve as a system of checks and
balances. For example, every test was
preceded by a test plan. Test plans were
circulated through the project team and
various departments within the company
for approval.
Finally, assembling a strong, adaptable
engineering and project management
team makes all the difference.
“The team was able to lead the project
over many different hurdles,” says Lei.
“As the recognized experts in the topic,
the team not only had to work with the
management and technical aspects, but
also to be able to communicate well with
everyone in and outside the company.”
Smart grid technologies
represent an opportunity to
enhance the value custom-
ers receive from the elec-
tric system. This transition
will be a significant chal-
lenge — one that involves
not only leveraging new
technology, but also mak-
ing major changes in the
way electricity is provided
and used. PGE is eager to
engage in the research and
development needed to
bring our local and regional
grid into the 21st century.
What’s
next
for PGE?

15
University of
Washington
UW’s electric grid gets smart with living laboratory
Higher education happens at the University of Washington
in more ways than one. For students, it’s academics.
For facilities, it’s smart grid. More than 250 buildings
on the university’s Seattle campus are temperature
conditioned. That’s more than 13 million square feet of
comfortable space to conduct research. And it goes to
good use, because UW has one of the biggest research
budgets among schools nationwide.
The scholastic setting provided a unique
perspective for the Department of Energy
demonstration. More than 20 million
people are enrolled in higher-education
programs across the country. That’s a lot
of students, not to mention researchers
and faculty. For that reason, college
campuses make an ideal environment for
advancing smart grid technologies.
“Finding solutions to real work problems
is a really important part of today’s
educational environment,” said Norm
Menter, UW’s energy conservation
manager. “Our student population
demands that the university be involved
in projects like this.”
UW is one of two universities, five
technical firms and 11 utilities across an
unprecedented five-state region selected
to participate. The university was
awarded $5.1 million in federal funds to
complete its $10.2 million project.
By the numbers
The average daily population on campus
is 60,000, and the average daily electrical
demand is 38 megawatts. This costs
the university about $1 million a
month — making it Seattle City Light’s
second largest customer. Even so, the
campus also has its own five-megawatt
steam turbine generator. The power
UNIVERSITY OF WASHINGTON
Seattle, Washington
ƒƒSeattle City Light’s second largest
commercial customer
ƒƒPopulation of 60,000
ƒƒ38 megawatts of demand
ƒƒElectricity bill of $1 million a month
INVESTMENT
$5.1 million
Highlights
ƒƒEnergy dashboard
ƒƒLiving laboratory
ƒƒFive-megawatt steam generator
Norm Menter (206) 221-4269
www.washington.edu
success stories

16
is distributed through a network of
underground utility tunnels.
Energy dashboard
drives decisions
Before the project, UW had just seven
meters on its Seattle campus to monitor
energy use. Now, there are more than
200 smart meters acquiring near real-time
data about energy consumption every five
to 15 minutes. These meters transmit the
data to a central repository. To see the data
and more accurately predict future energy
use, the project team built a console
to analyze and display the information
collected.
Data is analyzed and displayed on
“dashboards” that provide an at-a-glance,
graphical presentation of the energy use,
within just minutes of its consumption.
Anyone can view the data online and
compare a year-and-a-half worth of
information on each building’s energy
consumption during any hour, and see
how much that energy costs and patterns
of use over time. Engineers at the univer-
sity also use software tools to analyze
the data collected, helping UW eliminate
waste and save money.
One feature allows a comparison of energy
use by building at different times of the
day or year. That information is vital to
determining how to reduce energy use
and eliminate energy waste.
“The surprising thing we learned was that
energy waste is not the same thing as en-
ergy consumption,” said Menter. “Waste
occurs just about everywhere, but just
because you have high consumption in
a particular building doesn’t necessarily
mean that it’s being wasted. The informa-
tion is valuable for decision-making, but it’s
not the whole story.”
The dashboard raises awareness about a
building’s overall efficiency and provides
the opportunity to have a conversation
about why changes need to be made to
a building. This dialogue builds a common
understanding so that decisions are made
together across campus.
Sharing of data equals a need for improved
cyber security. As a public university, UW
has an open network. So coming into this
project, the university had to overlay a
private network onto its existing system.
That cost quite a bit of extra money. But
it was worth it. After all, having data, and
being able to store that data securely and
make it available to the public, is immensely
valuable to the research mission of UW.
A student energy
intervention
Of those interested in the data were —
no surprise — the students. The energy
use of freshmen in two residence halls
was looked at by fellow students to see if
a “technology intervention” could reduce
the freshmen’s energy consumption,
compared to a manual intervention.
In one hall, students received weekly en-
ergy-saving tips to encourage conservation
and to gain qualitative data. In the other,
volunteers received EnergyHubs, which
measure, communicate and control
individual energy use in real time. When
small appliances, electronic devices, TVs
or laptops are plugged into EnergyHub
power strips or outlets, the cost of using
each is displayed on a desktop monitor.
The monitor also displays daily energy
use, current energy in kilowatt-hours, and
monthly cost projections per appliance.
And they allow the user to set up sched-
ules for the appliances or remotely turn
them off through a smart phone app.
Using its smart meter infrastructure, the
research team was able to collect weekly
energy consumption data, analyze the
students’ energy use over 10 weeks, and
compare the energy use of students in
the two residence halls. But the study
yielded inconclusive differences between
the two groups, perhaps due to one
aspect of studying students’ energy
use in a university residence compared
to adults in their own homes: a lack of
monetary motivation.

17
These assets represent an investment that’s
going to be here for many years. We can use
the data to build a greater understanding
about how buildings use energy, and to
make the entire campus community more
intelligent about how we use energy. It’s a
change in our relationship with electricity.”
— Norm MenterUW Energy Conservation Manager
“One important long-term outcome of the
research was to raise student awareness
of the personal energy choices we all
make every day,” said Kelly Hall, a UW
graduate student on the research team.
The team believes the university should
not rely on student actions to reduce
energy consumption, but move towards
using more automated and integrated
systems.
A regional
transactive role
One part of the project, which spans an
unprecedented five-state region and
60,000 metered customers, is automating
the system for a regional benefit.
UW connected its steam turbine generator
to the demonstration project’s transactive
control system. Transactive control uses
an interactive, market-based signal to
increase or decrease energy consumption
to achieve greater efficiency in grid
operations. The signal is sent over a
multiple-utility footprint. Participants in the
project test the feasibility of increasing
energy use when wind energy is abundant,
typically at night, and reducing use during
peak hours when energy is most expensive.
“We integrated the steam turbines with
the system, so that the turbines would
respond and go into a nighttime setback
mode when they received a transactive
control signal,” said John Chapman, UW
executive director of Campus Engineering
and Operations. “The steam turbine gen-
erator concept has potential. I can see how
we could use it to vary the operation of our
generators to help the region integrate
renewables into the grid.”
But UW’s current generating system is
constrained in terms of how it could con-
tribute to a transactive control system. It’s a
cogeneration system: after the steam goes
through the turbine to generate electricity,
it then goes on to heat the campus. In
the summertime, there’s not much steam
demand. Only during the winter is there
some flexibility on the output.
Conceptually, UW could replace its
generator with something that has the
ability to interact with new technologies.
“With that type of system, we could bring on
maybe an additional 10 or 12 megawatts
anytime of the year to feed into the grid
whatever time of day it was required,”
said Chapman. “And we could do that for
a reasonable price, I think.”
UW also connected two standby diesel
generators to the transactive control
system as part of this project. But they
are more expensive to operate than the
steam turbines.
“I don’t think the economics would ever
pan out to run those and generate electricity,”
Chapman added.
There are also environmental requirements
that limit the use of diesel generators, so
UW will focus on its steam turbine.
UW created a demand reduction operation
strategy for five buildings on campus. As
part of the transactive control system, the
university could opt in to reduce electrical
demand at three different levels. These
strategies included changing discharge air
temperature set points, reducing fan static
pressure and limiting control valve positions.
5-megawatt steam turbine

18
As far as the impacts on operations, the university is just
getting started, but a solid foundation is now place.
Tools such as the dashboard allow UW’s energy engineers
to look for anomalies in energy consumption and deter-
mine which buildings they should take a look at first. The
dataset builds a greater understanding about how the
campus buildings use energy. And, the improved infra-
structure makes the entire operation more efficient, which
means there is potential to reduce the costs of education.
“That makes the entire campus and the entire community more intelligent about how we
use energy,” said Menter. “It’s a change in the relationship with electricity.”
What’s
next
for the University
of Washington?

19
Idaho
Falls
Power
Idaho Falls Power
Idaho Falls, Idaho
ƒƒLocally-owned and operated
since 1900
ƒƒLargest municipal utility in Idaho
ƒƒ27,000 metered customers, including
3,500 commercial customers
ƒƒInstalled 1,500 AMI meters
ƒƒGenerates 50 megawatts and sells
to BPA
Investment
$3.5 million
HIGHLIGHTS
ƒƒWireless mesh network
ƒƒElectric vehicles
ƒƒCapacitors
Mark Reed (208) 612-8234
www.idahofallsidaho.gov
Small city in Idaho gets smarter with automation
Idaho Falls is simply a smart city. Since 1900, the western
town has generated electricity by making use of the Snake
River, which runs right through it. Today, Idaho Falls Power —
which is known for its early adoption of tools to improve
system reliability — is testing some hefty smart grid
technologies as part of the Pacific Northwest Smart Grid
Demonstration Project.
A city-wide wireless
network
Idaho Falls Power services 23 square
miles within the city, which is framed by
wide-street neighborhoods and well-
educated residents — many of whom
work at the Idaho National Laboratory
nearby. So when the utility decided
to test smart meters through a city-
wide wireless network, most of their
technologically-savvy customers didn’t
blink an eye.
The wireless mesh communications
system allowed the utility to test a
number of new technologies, such as
automation of switches in substations
for outage restoration. Another benefit of
using the wireless network is improving
computer and electronic protections.
“We drastically improved cyber security
awareness and increased focus in that
area as a result of this project,” said Mark
Reed, Idaho Falls Power superintendent.
“That’s something near and dear to
my heart.”
Having a secured wireless system means
the utility can do more with its smart meter
system, or AMI — advanced metering
infrastructure — and integrate those
meters with the centralized computer
system of a substation’s control center.
success stories

20
Meters talk to in-home
displays wirelessly
The progressive utility has 13,250 smart
meters, including 1,500 meters that were
installed as part of this project. All 27,000
customers are expected to have a smart
meter by May 2015.
Eight hundred in-home display monitors
communicate wirelessly with the meters
of volunteers, allowing a real-time view of
their electric use either by the hour, day or
month. Usage trends and costs, as well as
important utility messages and alerts, are
also displayed. All the information will be
available on a web portal and mobile app
that customers can access by fall 2014,
making it even easier for households to
calculate daily energy costs and estimate
their bills.
For one long time resident, the
technology is about much more than
crunching numbers.
“I’ve looked at the climate data,” said
Jim Seydel, Idaho Falls Power customer.
“I believe we’re going to have more
extreme weather. I believe under those
conditions, we’re likely to have more
outages than we’ve had in the past
because of climate change. So, I’m
looking for ways that I can counter that.”
In short, these devices empower
customers to take ownership of their
energy use and planning. Still, about
135 customers have vetoed the meter.
“I think there is just some confusion about
what smart meters are,” said Matt Evans,
customer relations supervisor at Idaho
Falls Power. “When they Google ‘smart
meter’ they find some alarming things.”
But the majority of the community, which
attracts world-class outdoor recreationists,
regional business owners and culturally
savvy patrons, has embraced these
leading-edge technologies. They can be
found just about everywhere … even
on appliances.
Hitting the snooze
button on appliances
Back in 1934, Idaho Falls was one of the
first cities in the United States to adopt
devices that could prevent brownouts.
These devices were able to cycle water
heaters off, using frequencies, when river
flows were low or as households began
installing electric appliances and using
more energy.
Today, the methodology remains the
same — only the communication tools
are much more advanced. Loads can
now be shifted to later in the day when
the cost of electricity has fallen or demand
has fallen. For this project, 217 volunteers
tried a power control device. These devices
cycle off electricity to appliances when
the need for energy is highest. This
avoids unplanned power purchases,
which are more expensive.
Heating and cooling costs account for
most of the utility’s peaks. Forty-one
customers signed up for programmable
thermostats. With these “smart” in-
home displays, the utility can make
very subtle temperature adjustments
within households for brief periods
when energy use is highest — the utility
equivalent of rush hour traffic.
The newer systems are also more
advanced. Idaho Falls Power alerts the
customer before it makes any changes.
The thermostat indicates when the utility
plans to make a scheduled thermostat
adjustment, and the customer always
has the option to override or opt out of
the utility request.
Improving energy use
automatically
Another way to reduce energy consump-
tion is by automating the distribution
system. One little electronic device, a
capacitor, is helping to make this happen.
While capacitors have stored energy and
stabilized voltage and power flows on
distribution lines for decades, the process
is getting smarter with two-way commu-
nication. The stable and steady delivery
of electrons saves time and money. For
big industries, that savings can add up.
Making malt for brewing beer, for
example, takes a lot of energy. IFP’s
largest industrial customers are malt
houses, which benefit from something
called automated power factor control.
A power factor is a measure of the
efficiency of the power being used. A
power factor of 100 percent means the
voltage and current are cycling between
positive and negative in unison, but when
one lags behind the other, the power
factor declines. The lower the power
factor, the more power the generator has
to supply for each watt being consumed.
One way to improve the power factor is
by installing banks of capacitors, which
can automatically bring the current and
voltage closer to unity. Idaho Falls Power
purchased two capacitor banks as part
of the project — one for each of its large
commercial customers. The projected
wholesale energy savings is $37,750 per
year. But saving money isn’t the only
benefit.
As a result, we gained insight and knowledge on
the technology to help us forge into the future a
little more prepared with better ideas of where
we want to go.”
– Mark Reed, Idaho Falls Power superintendent

21
For Idaho Falls Power,
the next step is evaluation.
Assessing the feasibility
and cost-benefit of the
smart grid technologies
tested in the demonstra-
tion project is essential.
“It’s how we’ll determine which technologies have value
for expansion across the entire system,” said Reed.
And, of course, they’ll be sharing what they’ve learned.
What’s
next
for Idaho Falls?
An electric vehicle charges using stored energy from a nearby photovoltaic panel.
“It reduces the electric current on the
line,” said Reed, “which could defer
the large capital cost of an upgrade.”
Another way to use distributed
automation is through conservation
voltage reduction. In this case, CVR
reduces the overall voltage on the
residential feeder to 1,375 smart-
metered customers.
A “self-healing” grid
Let’s face it. Lightning causes power
outages. That used to mean a utility
worker would be dispatched to locate
the fault and manually reset switches on
the transmission lines to reroute power.
Now this can be done automatically
through fault detection, isolation and
restoration, or FDIR — sometimes referred
to as “self-healing” technology. This
smart technology can instantly detect a
fault and automatically reroute electricity
to keep customers from losing power
in the first place. The tool uses automated
switching between two distribution
system feeders and control algorithms
to isolate the problem and restore the
system.
Saving some for later
Electric vehicles can be great energy
storage units. Of course, these mobile
batteries also make great transportation
tools. Incorporate a solar panel and you
have quite a setup.
Here’s how it works:
The solar panel charges a stationary
battery during the day. That battery, with
10,000 watts of capacity, is hooked up
to the car-charging stations. When a car
is plugged in, it draws 3.35 kilowatts for
four hours from the stationary battery.
That means two or three electric vehicles
can be plugged in to receive a full charge.
“The integration work was outstanding,”
said Reed. “The AMI interface was really
fantastic.”
The drive behind the test is to integrate
distributed solar with distributed storage
to optimize grid efficiency. It works — but
with one problem.
The test was nearly complete when the
vendor went bankrupt. This has left Idaho
Falls Power with no access to the software
or any of the data that was collected. If
the vendor never returns with the data, the
utility is considering working with nearby
Idaho National Laboratory to explore
possible solutions to retrieving the data.

22
And by the
way ...
Project Landscape

23
Flathead
Electric Co-op
Flathead Electric Co-op
Kalispell, Montana
ƒƒLocally-owned & operated since 1937
ƒƒSecond largest utility in state
ƒƒ3,900 miles of line
ƒƒ48,000 customers
Investment
$2.3 million
HIGHLIGHTS
ƒƒSingle point of contact
ƒƒCompleted a systemwide AMI rollout
ƒƒHome Energy Network
For more information
Russ Schneider (406) 751-1828
www.flatheadelectric.com
With 48,000 members, Flathead Electric
Co-op is the second largest electric
utility in Montana. Yet it maintains the
cooperative spirit of neighbor helping
neighbor. When granted the opportunity
to help consumers reduce their energy
use during periods of peak demand and
save money on their monthly power bills,
Flathead put its members’ needs and
interests first.
With the project in its fifth and final year,
Flathead is planning for further investment
in some of the technologies it has tested.
The utility is also teaching others what it
has learned.
A solid foundation
Flathead was a prime candidate for the
project because it had already invested
in developing an advanced metering
infrastructure, a crucial component of
the two-way communication between
the utility and end-users. Households
fitted with these advanced meters allow
the utility to monitor electricity use in real
time and identify peak-use times, when
electricity is most expensive.
“This is different from conventional energy
conservation because, while participants
may not actually use less energy in total,
they may choose to use it at times of
lower cost to the co-op,” says Flathead
Regulatory Analyst Russ Schneider. “This
has the potential to ultimately reduce
power supply expenditures for members
and the co-op as a whole.”
Flathead’s objectives included completing
installation of the advanced metering
Building a smart grid the cooperative way
Tucked in the mountains of Glacier Country in Northwest
Montana, Flathead Valley’s grand landscapes and
unspoiled freshwater lake attract recreationalists year-
round. Legendary, small-town hospitality appears even in
unexpected ways — like the local electric cooperative’s
participation in the Pacific Northwest Smart Grid
Demonstration Project.
success stories

24
infrastructure in northwest Montana,
determining member preferences and
comparing the cost effectiveness of three
program options offered to members who
volunteered.
But first the co-op needed community
buy-in.
Peak Time
Flathead emphasized customer
education and outreach and put
tremendous thought into designing a
program that its members would support,
down to the project’s name. Instead of
the term “smart grid,” Flathead’s leaders
chose a name they felt would better
describe the pilot’s purpose and resonate
with members: Peak Time.
“I think that worked well for us. We wanted
to be very clear about what we were
trying to do as a cooperative,” says
Teri Rayome-Kelly, Flathead’s demand
response coordinator. “And we also
stressed what was in it for them — what
they would gain for participating. We
basically used any kind of communication
tool available and talked to every
community group that would listen. We
did a lot of boots on the ground stuff.”
Peak Time aims to help energy
consumers reduce energy use when
the demand for and cost of power is
highest. This type of adjustment in energy
consumption is called demand response.
Smart grid-enabled demand response
requires two-way communication
between the utility and the end-users.
I think the biggest thing that’s
misunderstood with smart meters or two-
way meters or remote meter reading is
there’s going to be more privacy intrusions
by that than having a person actually walk
around your house once a month to check
the meter. There’s a little bit of disconnect
on the privacy/security aspect of it with
the public compared to what was done or
what they’re willing to accept from other
technology.”
— Russ Schneider, REgulatory Analyst
The method for carrying out this
communication was also an important
consideration for Flathead. Based on
some initial reactions from members
about the use of wireless networks
to transmit information, the co-op
chose to use an “over the power line”
approach, and emphasized that in its
communications.
To gather the most information about
member preferences, Flathead offered
three options:
OPTION 1: In-home display
A free in-home display unit
notifies households of peak
demand times, signaling them
to reduce consumption until demand on
the system declines.
Participants receive a $5 monthly credit
and an annual rebate determined by their
energy consumption. If the participant’s
highest hour of use during the billing
cycle is during a non-peak time, the
participant receives $4/kilowatt for the
difference in consumption between the
highest non-peak hour and the highest
peak hour.
The in-home display was the least-costly
option to implement, at about $125
per member. Its purpose was to show
consumers how much electricity they
were using and when they were using it.
Due to some limitations of the emerging
technology, Flathead has been unable
to use the tool as it had planned, such
as to send volunteers data about their
current use or billing information. The
only information households receive is an
indication that it is a peak time, signaling
them to reduce their energy use until the
demand on the system decreases.
Keeping the households tuned-in to the
tool during the five-year demonstration
has been a challenge.
“There is a little bit of attrition on a long
project,” says Schneider. “Utilities need
to have an actionable activity for the
members on a regular basis in order to
keep them engaged.”

25
Teri Rayome-Kelly chats with residents to rally participation in Peak Time.
OPTION 2: Water heater
demand-response unit
A free demand-response
unit automatically cycles off
participants’ water heaters for up to two
hours during times of peak demand to
reduce energy consumption.
Members who volunteered for this option
receive an $8 monthly credit. The co-op
uses over-the-power-line technology to
operate each household’s water heater in
response to peak demands.
The water heater cycling has produced
the most reliable savings across most
peak demand events. On average, this
option reduced energy consumption by
0.58 kilowatts per unit. With an average
installation cost of $413, the utility
expects it could recover the investment in
three to five years.
“The demand response units attached
to hot water heaters are very reliable,”
says Rayome-Kelly. “I can’t think of any
significant challenges we’ve had with
those. When we started this,
we thought this test group would be
the hardest one to sign people up for,
because you’re hooking equipment onto
their water heaters. But people really
accepted that quite well. It wasn’t
a problem to get people to sign up.”
Flathead received zero complaints from
members regarding a lack of hot water.
OPTION 3: Home Energy Network
Volunteers paid $800 for new
appliances — a dishwasher, clothes
washer and dryer — plus an electric
water heater demand response unit
and equipment that enables the appli-
ances to communicate with the utility
over the members’ home wireless
internet connection.
Using a signal sent over the power line
from the integrated advanced metering
infrastructure system to each participant’s
wireless internet connection, energy-
efficient appliances can be cycled off
or put into an energy-saving mode
as needed to reduce demand on the
system. If the participant’s highest
hour of use during the billing cycle is
during a non-peak time, the participant
receives $4/kilowatt for the difference in
consumption between the highest non-
peak hour and the highest peak hour.
When Flathead offered a Home Energy
Network option, it didn’t take long for the
utility to realize it had taken on more than
it had anticipated.
“We hadn’t planned on being in the
appliance business,” said Rayome-Kelly.
“But as a small community, we don’t have
any big box stores, so we had to look for
a contractor to install those for us.”
Appliance handling and installation
scheduling became a newly acquired skill
for some.
“I can level a washer with the best of ‘em,”
Rayome-Kelly said.
While the smart appliances proved that
they could reduce household peak
energy use by up to 2.34 kilowatts, it
was the most costly option to implement.
It cost about $2,500 more to install the
smart appliances and related equipment,
compared to the cost of new traditional
appliances.
Flathead also learned that the integration
of different technologies can be messy.
Technical issues arose from the use of
interoperable appliances, which struggled
to communicate with the Home Energy
Network. Vendors had to learn about
new technologies and new products
and figure out how to make them work
together. Flathead also faced challenges
integrating its own internal systems with
the Home Energy Network.
At the end of the day, the co-op’s pilot
project gathered important data and
learned key lessons to improve future
implementation.

26
With a toolkit of expertise and lessons learned, the co-op
is ready to get started with a demand response program
that makes sense to the bottom line.
“We’re already planning to do an extended water heater
program,” says Schneider. “We’re planning to connect
1,000 water heaters each year for five years.”
What’s
next
for Flathead?

27
Northwestern
Energy
Small steps to a smarter grid
Listen to a planning meeting at NorthWestern Energy
and you’ll likely hear: deploy at the speed of value, and
stay on right side of the repair-versus-replace curve.
Decisions here are made very carefully. After all, this award-
winning, investor-owned utility serves one of the largest,
most geographically diverse territories in the region. With an
infrastructure that spans over 28,000 miles of transmission
and distribution lines across three states, planning ahead
is important. Especially as the 500,000 poles, components
and wires get older.
A plan to upgrade its basic distribution
system was already in the works when
the opportunity arose to take part in the
$178 million Pacific Northwest Smart Grid
Demonstration Project. Improving upon
existing infrastructure using smart grid
technologies just made business sense.
“We weren’t quite ready for it,” said
George Horvath, manager of automation
and technology for NorthWestern. “We
expected that the technologies would
advance, change and be improved over
two to three times during the course of
the project.”
So going small-scale was NorthWestern’s
solution.
With its $2.1 million investment, North-
Western also planned to learn from the other
participants.
Customer side of
the meter
A perfect urban area to test new tech-
nologies turned out to be Helena, Mont.
With 30,000 customers and an electric
load of 90 megawatts, Helena had
Northwestern Energy
Butte, Montana
ƒƒServing 349 communities across
Montana, South Dakota and Nebraska
ƒƒOne of the largest service territories in
the Northwest
ƒƒ28,000 miles of lines
ƒƒ400,000 metered customers
INVESTMENT
$2.1 million
HIGHLIGHTS
ƒƒDemand response program
ƒƒDistribution Voltage Reduction
ƒƒAdvanced AMI
communications network
ƒƒIn-home energy displays
Claudia Rapkoch (406) 497-2641
www.northwesternenergy.com
success stories

28
the right mix of customers and basic
systems.
First step: recruit participants. Around
200 residential customers and two
commercial buildings from the State of
Montana were enlisted to take part in the
nation’s largest test of new smart grid
technologies. It took two marketing
campaigns and extending the area beyond
Helena to reach recruitment goals.
Next step: install equipment. Residents’
homes were fitted with switches to
control appliances, outlet-type switches
that turn regular electrical outlets on and
off, as well as programmable thermostats
and energy system display devices.
Installing the equipment was easy.
Educating customers and learning from
the experience took more time.
Working closely with
customers
“We hired a company to work directly
with our customers and teach them how
to benefit from the equipment in their
homes and to learn to use it effectively,”
said June Pusich-Lester, NorthWestern’s
demand side management engineer.
Training included how to program the
equipment and use a web portal. A web
portal is another name for a dedicated
website that has special functionality.
ElizaWiley,IndependentRecord
The portal showed past energy use, as
well as the energy consumption of every
device connected to the network. A
monthly electronic newsletter was also
sent to educate customers.
The benefits were twofold. Customers
could see their energy use to better
understand ways to save, and North-
Western gained insight into what customers
want and what they are willing to do to
conserve energy.
Would customers respond to a reward?
Time of use and
demand response
Residential customers were set up for
time-of-use pricing. These programs
help the utility to control some of the
consumers’ electrical
load in response to
grid conditions and
the price of electricity.
Here’s how it worked:
Montana has a flat
residential rate, but
the demonstration
project offered a
regional price. So for
testing purposes, the
rate fluctuated. Each
customer received a
signal that displayed
the price of electricity
as low, medium or high depending on the
time of day, the day of the week and the
month or season.
Customers responded by adjusting and
programming the equipment, attached
to a home area network, based on
the pricing schemes. As a result, load
decreased during peak times of use.
“We rewarded our customers for energy
savings,” said Pusich-Lester. “With the
smart meters and the communication
network working together, we could read
energy usage in 15-minute increments.”
If a customer used less energy when prices
were high, NorthWestern credited the
customer’s monthly bill. As of September
2014, total savings from the time-of-use
pricing totaled $13,787 for all customers.

29
We’re going to have the benefit of all
the other, much larger projects from the
demonstration, reading through their
evaluations, and learning from them. It’s an
important part of our project, what we’ve
learned and accomplished, so now we can
better communicate about the smart grid
with our regulators and customers in the
future.”
— George Horvath,
manager of automation and technology
The system also gave the utility direct
control over some residential customer
loads.
“Now we are able to send demand
response events directly to the homes,”
said Pusich-Lester.
With the ability to control home appliances
using two-way communications, North-
Western reduced home temperatures or
turned off appliances when the price was
high in the middle of the day. Demand re-
sponse and time-of-use methods provide
flexibility while saving money.
Other technologies focus on overall
efficiency.
Voltage reduction =
efficiency
We’re all familiar with the concept of energy
efficiency. Consumers reduce power
consumption through choices in lighting,
insulation, appliances and many other
methods. Utilities have been working with
customers to improve energy efficiency
for more than 30 years.
But there’s a new player in town.
Distribution voltage optimization, or DVO,
lowers the energy consumption on a
whole feeder — the line that delivers
electricity from a substation to a home.
By dropping the voltage on a circuit —
while staying above the minimum level
necessary to operate electric devices —
the customer’s energy costs decrease.
“We flatten the voltage profile, make
voltage adjustments, and save energy for
the whole feeder,” said Horvath.
According to industry data, a potential
exists to shave one to three percent of
circuit load using this technique.
Utility side of
the meter
Keeping the lights on is a mission of
every utility. Until smart grid technologies
came along, distribution systems were
in the dark. Utilities were unaware of an
outage until a customer called to report it.
Now, new technologies on the utility side
of the meter use automation to improve
reliability by detecting a problem, isolating
it, and then restoring as many customers
to service as possible.
This type of system is called distribution
automation or self-healing technology.
Computer systems quickly react to electrical
issues in the system, like a fault in a feeder,
without intervention from an operator or
line worker. NorthWestern tested Fault
Detection, Isolation and Restoration, or
FDIR, software.
“We configured circuits with remote
capabilities, to monitor circuits with central
software, and to be able to reconfigure
circuits in case of issues,” said Horvath.
Since October 2012, the system has
already automatically reconfigured
and mitigated customer service on the
feeder for two outages in Helena. That
means shorter outages for customers
and resource savings for NorthWestern.
Testing technologies to solve real-
time, real-world problems is what the
demonstration is all about. Still, many
lessons were also learned in the research
and development initiative.
Lessons to share
NorthWestern’s goal was to make slow
improvements to prepare for larger business
objectives and to learn how to invest
in products and services that have
longevity.
“We definitely realized our objectives,”
says Pusich-Lester.
One unexpected lesson was in selecting
vendors. Some vendors evolved or went
out of business, leaving the utility stranded
with products that didn’t work. The
complexity of integrating components
from different vendors while building the
systems was also unexpected.
Other notable lessons from
NorthWestern:
ƒƒ Start with a small project — it makes
the business case analysis easier
ƒƒ Emphasize the importance of customer
education with project stakeholders
ƒƒ Integrate a customer information
system to smart grid at the start
ƒƒ Work closely with customers to
understand new system enhancements
and in-home display features

30
ƒƒ Billing system integration for new
programs requires significant planning
effort
ƒƒ Build a distribution management
system first, then add smart grid
ƒƒ Allow sufficient time and money
cushion for communication backbone
ƒƒ First-time equipment rollouts have
engineering, IT system, communication
and business program learning curves
ƒƒ In your risk analysis, consider the
possibility of a vendor going out of
business during your deployment
“The project has helped to mold our thinking
on how we plan on a larger scale,” said
Horvath. “We might do things differently
now from the big picture perspective.”
During the project,
NorthWestern kept a
clear focus on its basic
infrastructure and worked
to remain on that right
side of that repair-versus-
What’s
next
for NorthWestern?
That includes keeping
customers engaged.
For both the utility and the
customer, the chance to
become better informed,
educated and experienced
with the technologies
will prepare everyone for
the utility of the future,
whatever that may bring.
replace curve. Outcomes
from the project will
inform future smart grid
improvement processes
and projects.
“We will continue to invest
in the basic infrastructure
and incorporate new tech-
nologies where they make
sense,” said Horvath.
“This project provided a
foundation for us to evalu-
ate something much larger
going forward.”

31
Milton-
Freewater
MILTON-FREEWATER CITY LIGHT
& POWER
Milton-Freewater, Oregon
ƒƒLocally-owned and operated
since 1889
ƒƒAverage annual sales:
118,000,000 kilowatt-hours
ƒƒ4,550 customers
INVESTMENT
$1.8 million
HIGHLIGHTS
ƒƒCompleted AMI rollout
ƒƒDirect load control/DR
ƒƒFive-megawatt reduction
ƒƒConservation voltage reduction
Tina Kain (541) 938-8238
www.mfcity.com/electric
Milton-Freewater is the only public utility
in Oregon chosen to take part in the
nation’s largest smart grid test.
With Milton-Freewater’s $1.8 million
investment and DOE’s matching funds,
the rural utility upgraded its historic
demand response program and tested
some newer technologies, such as
voltage reduction and voltage-sensing
water heaters.
Of the 60,000 metered customers involved
in the regionwide project, Milton-Freewater
City Light and Power is the smallest
participant with only 4,550 customers.
The utility did not hire any additional
staff except for a contractor to perform
installations, because the utility’s only
electrician had retired.
Blazing the trail for
demand response
When not at his cherry orchard, retired
city electrician Bill Saager enjoys the
cowboy shooting range just outside of
town. The 75-year-old bandana-wearing
quick-draw installed the city’s original
demand response units — all 500 of them.
But getting and using a contractor’s
license wasn’t easy. Saager convinced the
State of Oregon Construction Contractors
Board to forgo the insurance and bonding
requirement because he was only doing
work for the utility, not the customer.
Clearly, Saager is a fan of smart technology.
“I think that utilities are really missing the
target if they don’t pursue some type of DR
Milton-Freewater: A frontier for new technology
Oregon’s oldest city-owned utility is far from old-fashioned.
In fact, it’s a power pioneer in the Pacific Northwest.
Since 1985, Milton-Freewater City Light and Power has
reduced peak energy use with a technique called demand
response. Demand response may not be the talk of the
town, but it’s still a big deal to this homegrown utility. And
it’s one of the many technologies the Pacific Northwest
Smart Grid Demonstration Project intends to advance.
success stories

32
in the future,” said Saager. “You can really
extend the capabilities of your system.”
Milton-Freewater’s original demand
response program used a radio energy
management system, or REMS, to
control electric water heaters and electric
heating and air conditioning systems. A
centralized computer system monitored
the power demand and sent a radio signal
to the REMS units to cycle off connected
loads to reduce energy when the peak
demand set-point was reached.
The city’s goal of the Pacific Northwest
Smart Grid Demonstration Project has
been to enhance its already highly
successful demand response program.
Listen. Respond.
Repeat.
To do that, the newer technology must
go one step further, by listening and
responding from both sides of the com-
munication. With a smart meter system
that uses two-way communications, the
utility confirms that the demand response
units receive the signal and controls the
amount of time the electricity is shut
off. The goal is for the entire demand
response process to go unnoticed.
Master Station
(DRU Management Software)
DRU
(Demand Response Unit)
Water Heater
Air Conditioner
Water heaters, electric heaters and air
conditioners are connected to the demand
response system to trim energy use when
a certain set-point is reached. Up to three
megawatts can be reduced by shaving the
energy used in 754 customers’ homes,
businesses and even churches.
Replacing the old units with the newer
models spurred a lot of questions. Many
customers didn’t know the units existed.
A few were suspicious of the utility installing
new, more intelligent units. But only a few
opted out.
“We found that many homes had changed
tenants,” said Tina Kain, engineering
technician for the city. “New residents
were unaware of the DR units, which is a
great sign. The undisruptive units helped
residents save money without even
knowing it.”
To entice participation, a rate discount
was offered to customers:
ƒƒ 2.5 percent for water heaters
ƒƒ 2.5 percent on electric heating
ƒƒ 1 percent for air conditioning
DR is used as a last resort in the peak
shaving process. When the system begins
to approach its peak energy use, the first
step is to reduce voltage by 4.5 percent.
Next, the city shuts off the wells that are
connected to the centralized computer
system. Finally, DR units are employed.
Reverse order restores the system to its
original state.
The incredible value of
the smart meter
Every customer of Milton-Freewater City
Power and Light is now set up with a
smart meter that uses two-way commu-
nication over the power line. With these
more advanced meters, energy use is
monitored every fifteen minutes. That
means better customer service, such as
helping homeowners troubleshoot high
bill complaints and remote meter read-
ing. On selected meters, a device called
a disconnect collar, which allows for a
remote disconnect or reconnect, was
installed.
One of the biggest benefits is a smart
meter’s ability to quickly detect an
outage. Previously, the utility wasn’t
aware of an outage until a customer
called it in. A crew was then dispatched
to investigate and do the repairs. Often,
the process could take hours. Now, many
outages are fixed in minutes, saving
the utility both labor and transportation

33
You can see from our history that Milton-
Freewater City Light and Power is innovative
and forward thinking. It’s about planning
ahead. We all know that electric rates
probably aren’t going to be going down any
time soon, so if a new technology pencils
out now, it’s going to be more beneficial in
years to come.”
– Rick Rambo, the City of Milton-freewater
Electric Superintendent
expenses as well as providing better
service to the customers.
Conservation voltage
reduction
Conservation voltage reduction is Milton-
Freewater’s first step to address a peak
on the system. Substation voltage
regulators lower the system voltage
by 1.5 volts on four feeder lines out of
the Milton Substation. This reduces the
megawatts used on the entire system
while still maintaining adequate distribu-
tion voltage.
To test the theory that every 1 percent
in voltage reduction leads to a 1 percent
reduction in kilowatt-hours used, Milton-
Freewater reduces voltage one week,
and then returns it to the status quo the
next. By alternating weeks, the utility will
be able to compare the two datasets
and calculate the benefits once the
demonstration is complete.
Specialized water
heaters
To further test possibilities with conserva-
tion voltage reduction, Milton-Freewater
installed 100 demand response units on
water heaters that operate when the city’s
voltage reduction occurs. The demand
response units are programmed to sense
voltage and turn off connected load.
Although the water heaters worked well
with the voltage reduction system, they
didn’t work so well with another part of
the project — the transactive control
signal. This signal is being tested as part
of the demonstration across a multiple
utility footprint to assess the feasibility of
automating the trade of energy based on
many conditions, such as the availability
of wind or solar power, for a regional
benefit.
When the transactive control signal acti-
vated a voltage reduction, the demand
response units turned off the connected
water heaters, and they stayed off until
the voltage reduction ended. When the
signal lasts longer than five or six hours,
the customer may run out of hot water,
resulting in customer complaints and
countering the city’s goal of ensuring
demand response goes unnoticed.
Sizing up the study
Even though the city has been doing
demand response for three decades,
testing new technologies presented
challenges.
First, differences between the original
and new demand response systems
were disappointing. The old REMS units
operated 20 minutes on, 15 minutes
off, so Milton-Freewater could reassure
customers that their water heaters would
be turned off no longer than 15 minutes.
But the new units turn on and off in an
inconsistent, unpredictable pattern, which
is a little more difficult for customers to
accept.
And that wasn’t the only challenge with
the units. They all cycled on or off at the
same time, creating their own peaks and
valleys. Innovative solutions were needed
to stagger the units.
Data storage is also a problem. Unless
the data is manually extracted from the
unit before its next operation, the data
is lost. That means the utility cannot
determine how well the unit worked for
that cycle. To work around this issue, the
research laboratory will analyze meter
data to determine load fluctuations from
the demand response units.
Overall, lack of resources has been one
of the largest challenges for the small
rural utility — the employees had to learn
a whole new system while doing their
regular jobs. But that also demonstrates
the city’s dedication to keeping rates low.
“Every little bit counts,” said Bill Saager,
the retired electrician-turned cowboy.

34
As a result of the lessons
learned from the project,
the city plans to discon-
tinue conservation voltage
reduction. Even though
it has provided some
benefits, operating more
than one voltage reduction
system at the same time on different feeders was confus-
ing for work crews.
Furthermore, once the project concludes, the city will
explore transactive control opportunities based on the
needs of the city and the potential benefits.
Other ideas for the future include a customer pre-pay
system so that energy use can be managed based on an
individual family budget.
“We’re at the point of trying to learn what we can do
with the system,” said Rick Rambo, the electric utility’s
superintendent. “I know we’re not using it to its full
potential.”
Still, the tried and true prevails. Demand response will
continue as it has since 1985 across the city’s entire
electrical system, with fine-tuning of the operation as
needed and with very little impact on the customer.
What’s
next
for Milton-Freewater?

35
lower
valley
energy
Lower Valley Energy
Afton, Wyoming
ƒƒBegan in 1937 with 10 members
ƒƒProvides electricity, natural gas
and propane
ƒƒ5,616 square-mile territory
ƒƒ26,406 electric customers
ƒƒ195 megawatts
Investment
$1.2 million
HIGHLIGHTS
ƒƒAdaptive Voltage Control
ƒƒComplete AMI rollout
Rick Knori (307) 739-6038
www.lvenergy.com
Cold-climate co-op heats up with smart grid
Lower Valley Energy provides electricity to one of the
biggest resort towns — Jackson Hole, Wyo. — in one of
the coldest climates in the Northwest. At the southern
base of the Grand Teton and Yellowstone national parks,
out-of-town visitors and residents alike rely on the home-
grown electric co-op for heat, hot water and light —
especially during cold snaps when the demand for power
is highest.
That’s one reason Director of Engineering
Rick Knori wanted to complete the
utility’s deployment of its smart grid
metering system and help its more than
26,000 electric customers better under-
stand their energy use. That opportunity
surfaced with the Pacific Northwest
Smart Grid Demonstration Project,
With a focus on exceptional customer
service, reliability and low rates, Lower
Valley Energy jumped on the chance
to improve the way it provides services.
Smart meters and
demand response
Before the project, more than 12,000, or
nearly half, of Lower Valley’s members
had smart meters that allow for two-way
communications between the utility and
end-user. As of March 2014, 100 percent
of its members had smart meters installed
in their homes. This technology is a
necessary component of many smart
grid technologies, including water heater
demand response, which allows a utility
to cycle off participants’ water heaters
during times of peak demand to reduce
energy consumption.
High-end tourism is big business in the
Grand Teton area. One county in the
Lower Valley service area is consistently
rated one of the top five wealthiest counties
in the United States. So, it’s no surprise
that hot water is a hot commodity. Getting
a cold-climate community warmed up to
success stories

36
a program that even hinted at the risk of a
cold shower was a tough sell.
A $15 a month incentive to participate
in the demand response program just
wasn’t enough for some members, but
for others it was worth a try. Ultimately,
the co-op deployed more than 500
demand response units and used them
to temporarily turn off customers’ water
heaters during periods of high demand,
when energy prices are highest, thereby
reducing energy consumption.
“They worked excellent,” said Knori.
“These are going to be long-term assets
that we keep and control.”
Now there are 100 people on Lower Valley
Energy’s waiting list for a water heater
demand response unit.
Adaptive voltage
control a surprise
The most successful assets Lower Valley
deployed were tools for adaptive voltage
control, which can reduce a customer’s
overall voltage during brief high-demand
periods and result in short-term demand
reductions.
Using regular feedback from its customers’
meters, Lower Valley reduced voltage —
and therefore demand — during peak
load periods at the utility’s East Jackson
Substation. This technology provided the
greatest benefit for the least investment of
time and money.
Warren Jones, Lower Valley’s distribution
engineer, programmed the adaptive
voltage control signals.
“I think it was a surprise for us how well
the adaptive voltage control worked,” said
Jones. “That’s the one thing I would suggest
to other utilities that have advanced
metering infrastructure in place. It does
open up some opportunities for a utility to
use that intelligence to actually lower your
voltage.”
Adaptive voltage control has the potential
to greatly lower future monthly demand
charges paid by Lower Valley to
Bonneville, reducing energy costs to
customers. The test case also proved
that Lower Valley can easily expand
adaptive voltage control to all of its
distribution system substations in the
coming years.
Solar success
Lower Valley wanted to capture wind
and solar power during the day, store
it in batteries and discharge it during
the utility’s two-hour morning peak.
The purpose was to test whether new
technologies could reduce transmission
system losses and improve voltage
stability on a 60-mile distribution line
to Bondurant, Wyo. At its Hoback
Substation, Lower Valley installed a
system of renewable energy resources
and battery storage, including one
15-kilowatt solar photovoltaic,
one 20-kilowatt windmill set and a
200-kilowatt-hour battery.
“The solar and inverters worked flawlessly,”
said Knori. “We’re getting about a 17 to
18 percent capacity factor out of those
units. And they’re working trouble-free.
But the windmills were kind of a bust.”
After two years of operation, the total
output of the four windmills was about
80 kilowatt-hours. Lower Valley installed
an anemometer on the windmills to prove
to the vendor that the turbines were not
producing to the expected capacity. But
by the time the data was available from
the anemometer, the vendor was out of
business.
The battery storage — the newest of the
technologies — also presented some
challenges. The batteries arrived damaged
and had to be replaced, which caused
a delay. After a couple of programming
issues were worked out with the vendor,
the batteries were up and running, but at
half the expected 120 kilowatts of storage
capacity.
In-home displays,
in the drawer
Lower Valley also installed in-home display
units to provide consumers information
about their energy consumption. It was
a lot of work for crews to install the 400
devices. Yet with minimal customer
feedback, the tool’s impact on consumer
behavior is unknown.
Knori believes that few customers are
paying attention to the display units
because newer tools, such as smart
phone applications that perform the same
function, outpaced the in-home display
technology.
Lower Valley consumers have been very excited
to see the new technologies related to smart
grid, and that we have been doing pilot projects
to improve their power quality and efficiency.”
– Rick Knori, LVE Director of Engineering

37
Continued use of the hot
water heater demand
response units will help
Lower Valley keep electric
bills affordable. As energy
costs continue to increase
over time, Lower Valley
might decide to expand its demand response program.
By installing the adaptive voltage control technology to
additional substations, the co-op will take advantage of
even more energy savings.
Finally, with the help of the solar array, Lower Valley
Energy looks forward to keeping more electrons where
they belong by avoiding the losses that typically occur
over long distances.
What’s
next
for Lower Valley?

38
And by the
way ...
Profile of Battelle
In the Pacific Northwest Smart Grid Demonstration
Project, Battelle leads a collaborative effort that includes
the Bonneville Power Administration, 11 utilities and six
technology companies. Battelle also was a partner in the
AEP Ohio gridSMART Demonstration Project.
Battelle has been headquartered in Columbus, Ohio, since
its founding in 1929 and is a research and development
organization that also designs and manufactures
products and delivers critical services for government
and commercial customers. Battelle’s contract research
portfolio spans consumer and industrial, energy and
environment, health and pharmaceutical, and national
security. As part of its government-related work, Battelle
manages national laboratories, including Pacific Northwest
National Laboratory in Richland, Wash.
Battelle is the world’s largest nonprofit research and
development organization, with over 22,000 employees at
more than 60 locations globally. A 501(c)(3) charitable trust,
Battelle was founded on industrialist Gordon Battelle’s
vision that business and scientific interests can go hand-
in-hand as forces for positive change. Battelle’s strong
charitable commitment to community development and
education includes a focus on staff volunteer efforts;
science, technology, engineering and mathematics (STEM)
education programs; and philanthropic projects in the
communities Battelle serves.

39
Peninsula
Light Co.
Smart grid provides power bridge to Fox Island
Nearly half of Fox Island’s 1,200 residents moved here
to retire by the water. They sail. They hike. They kayak
in scenic Puget Sound. But the highly educated maritime
residents also expect the same reliable electricity they once
enjoyed in the city. That was a challenge for the utility that
relied on aging cables to deliver the island’s electricity.
Yet it was also an opportunity to test new
technologies to improve service, and the
reason Peninsula Light Co. applied to
participate in the Pacific Northwest Smart
Grid Demonstration Project.
PenLight invested $1.2 million in the
$178 million cost-share project. Just in
time, too.
A critical need
PenLight serves all of Fox Island, which,
given its watery surroundings, has no gas
service. That means many residents and
businesses are dependent on electric power
for everyday needs. Two cables deliver
electricity to the island: one submarine cable
and the other attached to a bridge.
“During the summer of 2010, the submarine
cable that was installed in 1970 started to
fail,” said Jonathan White, PenLight director
of Marketing and Member Services. “An
analysis determined that if the temperature
fell below 20 degrees Fahrenheit, the
ability to maintain load on the island’s
remaining circuit would be difficult.”
To cope with potential outages, a com-
prehensive strategic plan was developed.
The plan included rolling blackouts, backup
diesel distributed generation and a smart
grid program.
“Fox Island became a smart grid test bed,”
said Mike Simpson, PenLight’s manager
of Engineering. “Knowing there was an
aging issue with one cable, we thought:
let’s look at demand response to reduce
the load.”
PENINSULA LIGHT Co.
Gig Harbor, Washington
ƒƒMember owned since 1925
ƒƒSecond largest membership of any
co-op in Northwest
ƒƒ997 circuit miles of line
ƒƒ112 square-miles of service territory
ƒƒ31,000 metered customers
INVESTMENT
$1.2 million
HIGHLIGHTS
ƒƒPower Sharing
ƒƒPower line-carrier system
ƒƒSelf-healing network
ƒƒIntegrated volt-VAR control
Mike Simpson (253) 857-1580
www.PenLight.org
success stories

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